Presentasi Premiere oil

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2011 Annual Results Presentation 22 March 2012


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22nd March 2012 | Page 1

Forward looking statements

This presentation may contain forward-looking statements andinformation that both represents management's currentexpectations or beliefs concerning future events and aresubject to known and unknown risks and uncertainties.

A number of factors could cause actual results, performance orevents to differ materially from those expressed or implied by

these forward-looking statements.


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Agenda

Premier today

2011 financial results

Operations update

Exploration update

Summary

Simon Lockett

Tony Durrant

Neil Hawkings

Andrew Lodge

Simon Lockett


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Over the last 6 years …

4 0 %

3 3 8 %

7 2 %

8 0 %

Over the period, NAV/share CAGR of 14.2%excluding oil price effects


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Premier today...

Acquire Licence

Gate

Drill Decision

Gate

Appraisal

Approval Gate

Project

Extension

Gate

M E A P

N o r t h S e a

A s i a

Pre-Development

AppraiseDrillEvaluate

LEADS PROSPECTS MATURE PROSPECTS

... is in the strongest position inits history

• Clear path to 100,000 boepdfrom existing projects

• >1.5 billion of prospectiveresources in the exploration

portfolio• Fully funded programme with

strong and rising cash flows

• Proven capability to deliveracross the portfolio


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2011 highlights...

• Increased production to 60,000 boepd at year end

– Chim Sáo and Gajah Baru onstream

– Next generation of development projects progressing• Increased reserves and resources to 527 mmboe

– Exploration success at ~$5/bbl post-tax

– Acquisitions at ~$8/bbl

• Increased financial strength

– Cash and undrawn facilities of ~$1.4 billion

– Strongly rising cash flows

– Record profitability

– Continued access to bond and bank markets at favourable rates


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2011 financial results


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Record profitability

12 months to31 Dec 2010

Operating costs ($/bbl)

2011 2010

UK $39.5 $28.7

Indonesia $11.1 $8.5

Pakistan $2.4 $2.0

Vietnam $16.6 –

Group $15.9 $13.9

Highlights12 months to31 Dec 2011

Working Interest production (kboepd)

Entitlement production (kboepd)

Realised oil price ($/bbl) – pre hedgeRealised gas price ($/mcf) – pre hedge

Sales and other operating revenuesCost of sales

Gross profit

Exploration/New Business

General and administration costs

Operating profit

Financial items

Profit before taxation

Taxation credit

Profit after tax

42.8

38.3

79.76.3

$m

764(531)

233

(87)

(18)

128

(27)

101

29

130

40.4

37.7

111.98.5

$m

827(415)

412

(211)

(25)

176

(34)

142

29

171

• Net impact on 2011 of $23 millionpost-tax

• 25% of 2012 production hedged ataverage of $100/bbl

• Minimal hedging beyond 2012

• All b/fwd losses recognised asdeferred tax asset

• $1.36 billion allowances carriedforward into 2012

• No UK CT cash taxes until 2018 under

existing model using $75/bbl

Hedging

Taxation


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Rising cash flows

Cash flow from operations

Taxation

Operating cash flow

Capital expenditure

(Acquisitions)/disposals, net

Finance and other charges, net

Pre-licence expenditure

Net cash flow


$m2011

DevelopmentExploration

Estimated capex split ($m)

433228

661

Regional split ($m)

505

(69)

436

(514)

13

(70)

(19)

(154)


$m2010

349165

514

530

(44)

486

(661)

(90)

(50)

(23)

(338) North Sea$302mAsia

$301m

Total$661m

MEAP$58m

Outlook

• Operating cash flow increased by 11%; significant growth expected in 2012


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Strong liquidity position

Cash

Bank debt

Bonds

Convertibles

Net debt position

Pro forma Gearing

Cash and undrawn facilities

at 31 Dec 2010$m

300

(488)

( – )

(218)

(406)

26%

1,202

at 31 Dec 2011$m

309

(484)

(341)

(228)

(744)

30%

1,116

Outlook• Current debt funding costs average 5% (fixed) and 3% (floating)• Additional bank and bond debt raised post year-end of $585 million raising cash

and undrawn facilities (after some debt repayment) to $1,400 million by mid-March


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Fully funded programme

1400

Investment Profile(US$ million)

400

200

0

500

700

900

20132012 2015

800

600

100

300

2014

1000

1100

Exploration Expenditure

Development Capex1300

1200

Note: assumes exploration expenditure of $250 mm pa from 2013

2012 outlook

•Forecast full-year 2012 spend of ~$740million (development) and $220 million

(exploration)

•Total capex covered by cash flow for 2012at current spot prices

Forward funding

•Forward profile funded by cash flow andfacilities even at $60/bbl

•Significant capacity to increase spend on

exploration and new development projects

Outlook• Rising production generates $2 billion post-tax cash flow in 2015 at $100/bbl


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Operations update


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Operations highlights

• Chim Sáo and Gajah Baru onstream in October

– Deliverability exceeding expectations

• Realising further value from producing assets

• Continued progress on the developmentportfolio:

– Huntington and Rochelle progressing

– Solan project sanction expected soon

– Development studies for Catcher well-advanced

• On track to reach 75,000 boepd run rate byyear end 2012, once Huntington and Rochelle

onstream• Anticipate reaching 100,000 boepd when

Catcher comes onstream in 2015


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Production update

• Year-end target of 60,000 boepd achieved

– Full year production 40,420 boepd

– Strong gas demand in Pakistan and

Indonesia, combined with good facilitiesperformance

– Improved Balmoral production in H2, asmaintenance issues were progressed

• Wytch Farm acquisition adds ~2,500 boepd net• Production at Kyle (1,760 bopd) shut-in since

December 2011

• 2012 full year production forecast 60,000-65,000 boepd, with key variables being

– Timing of Huntington first production

– Ability to capitalise on excess deliverabilityat Chim Sáo and Gajah Baru

50

Production (working interest)(kboepd net)

20

10

0

60

2007 20102008 2009 2012E

30

Asia

MEAP

North Sea

2011

40

70


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Natuna ‘A’ 2015

Block A – strong production performance

Anoa & GSA1

• Producing at current maximum capacity

– 170-180 BBtud

• Phase 4 expansion project underway

– Raising capacity to 200 BBtud

• Pelikan will add 70 BBtud of capacity

Gajah Baru & GSA2/3/4

• Currently producing at 60-90 BBtud

• DCQ increases from 50 to 90 BBtud at end Q1

– 200 BBtud well deliverability

• Indonesia will shortly take an additional 40 BBtud

when the domestic swap agreement is signed

Outlook

• Series of new field developments will maintain rates

• Exploration is adding additional reserves


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Singapore Gas Market – sales are increasing

Singapore demand for gas will increase

• Existing pipeline supplies are naturally declining

• LNG supplies must commence and increase

• But supply diversity will be maintained, and beunderpinned by 90% Take or Pay contracts

• GSA1 demand expected to remain between DCQand Max Rate (341-392 BBtud)

Premier’s GSA1 market share is increasing• Block A contractual market share of GSA1 is 37%

– 2011 Block A actual share of deliveries was42%

– Block A share of remaining reserves dedicated

to GSA1 has increased to 59%

– Other GSA 1 suppliers are expected to drop to150-100 BBtud in 2015-2016

• GSA 1 market available to Block A could increaseto 200-250 BBtud in 2015-2016


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Chim Sáo – delivered and ramping up

• First oil achieved, safely and on budget, inOctober 2011

• Currently producing 25,000-30,000 bopd

– Gas exports add a further ~4,000 boepd

– Rates limited due to water injectiondelays

– 9 production wells could reach

40,000 bopd

– Vessel capacity is 50,000 bopd

• MDS5/6 reserves have increased by10 mmbo


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Chim Sáo – uncovering upside potential

Chim Sáo North West

• Chim Sáo North West discovered in August 2011

• Additional gross resource estimate 13 to 20 mmbo

• Near vertical appraisal well scheduled for mid-2012

• Development will be via existing facilities

Additional Reservoirs

• Further reserves potential is beingfound in reservoirs other than MDS5/6

Tie-in of Dua

• Government of Vietnam approvedODP in December 2011

• Long lead items being purchased

• Project sanction expected 1H 2012,first oil 2014

2000m

3060mss

ChimSáo

West Closure

Far Closure

Near Closure


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Kadanwari – getting more from a mature field

Kadanwari field

• Came onstream in 1995

• Highest gas price in Pakistan

• 2008-2012, five new gas compartments discovered:

– K-27 tied-in to system at 45 mmscfd in 2012

– K-28 and K-30, which tested at 30 mmscfd and50 mmscfd respectively, will be tied-in by mid-2012

• Production levels expected to be at 110 mmscfdduring 2012-2014

• Further exploration well planned for 4Q 2012

Upside potential• 550 bcf of tight gas potential identified in 2011

• 3 well pilot project planned for 2012


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Wytch Farm – motivated operator finding upside

Increased equity

• Increased Working Interest in Wytch Farm by17.715% to 30.1% in 2011

– ~4,500 boepd of net production in 2012 – Adds ~11 mmboe of net reserves

Upside potential

• Initiated active drilling programme to 2017 and

beyond to increase deliverability – Infill drilling in producing reservoirs to

accelerate production and optimiserecovery

– Bringing into production of satellite

discoveries onshore

• Long term production and reserves upsidethrough waterflood optimisation and EOR

• Working with new operator Perenco to

maximise value


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Huntington and Rochelle – progressing to first oil

• Successful development drilling campaign

• Phase 1 sub-sea installation completed

• CATS gas transportation agreement signed andshuttle tanker contract awarded

• Upgrade of the Voyageur FPSO proceeding

• Operator is expecting first oil in Q4 2012

• Rochelle area agreement executed May 2011

• Approval of FDP for East and West Rochelle

in 2011

• Scott platform modifications underway

• Subsea installation to commence in June 2012

• First gas expected in November 2012

Huntington Rochelle


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• Premier is Operator with 60% equity

• Development Concept:

– Subsea wells and storage tank

– Processing deck on a conventional jacket

– Reserves estimate ~ 40 mmbo

– Initial rate of 22,000 bopd

– Capex of ~$850 mm with $30 mm/year opex

• Premier will provide Chrysaor with:

– $50 million carry

– Corporate loan for the balance of their equity

– Loan recovered through Chrysaor’s cash flow

• Will qualify for new “Small Fields Allowance”

• Internal approvals are in place and seekingpartner and DECC approvals before end April

Solan – approaching project sanction


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Catcher Area – selecting a development concept

• Further 2011 drilling resulted in:

– STOIIP estimates of ~260-290 MMSTB

– Reserves estimates of 80-130 MMSTB

– Production rate of 50-70,000 bopd

• EnCore acquisition has completed

– Premier in place as Operator with 50% equity

• Conceptual Engineering studies completed

– Capex estimates range from $1.6bn for a leasedFPSO to $2.8bn for a central fixed platform

– JV concept selection process is underway

• New “Small Fields Allowance” will apply to seperate

accumulations on block

• Targeting sanction by year-end with first oil in 2015

FPSO and Subsea Wells

CPP, Bridge-linked WHP and Subsea Wells


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Reserves and resources – continuing growth

600

2007

450

400

350

0

150

200

250

300

2008 2009

100

50

Reserves and contingent resources(mmboe)

Production Additions &

Revisions

End 20112010

2C contingent resources

2P reserves

296

550500 230

227

261

Reserve replacement ratio of 333%


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A clear path to 100,000 boepd

120,000

Production outlook(bbls/day)

40,000

20,000

0

60,000

2012 20142013 2016

100,000

80,000

2015

1100

Development capex(US$ million)

400

200

0

500

700

900

20132012 2015

800

600

100

300

2014

1000

2016

At $100/bbl, expect post tax cash flow of ~$2 billion in 2015

Pre-Development

Sanctioned Projects

On Production


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Exploration update


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• Focus on geologies we know well

– Rifts or frontal fold belts

• Target best plays in basins ofchoice

– Play master approach

• Deliver 200 mmboe of 2P reserveadditions by end 2014

• Invest up to 30% of annual cashflows in exploration

• Gated process to decision making

Exploration strategy

Old New

Ol d

1. Premier capabilitiesand niche strategies

3. Technology capabilitiesand resource

diversificationopportunities

Ol d

N ew

2. Leverage Premiercapabilities in newareas

4. Identify long termopportunities forgrowth and approachto de-risk investment

N ew

Old New

G e o gr a

ph i e s

Themes

Themes

G e o gr a

ph i e s

AsiaMEAP &

Exploration

NewBusiness

North Sea


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2011 highlights

Exploration drilling

• Notable discoveries at Burgman in the Catcherarea in the UK, and CRD and Chim Sáo NorthWest in Vietnam

• 12 out of 21 exploration and appraisal wells drilledin 2011 successful

• Additional successes to date in 2012 with AnoaDeep in Indonesia and K-30 in Pakistan

• Remain on track to deliver 200 mmboe by end2014

– 70 mmboe added to date

New ventures

• 2011 highly successful for new acreage capture inNorway, UK and Kenya

• With lead and prospect maturation, greater visibilityfor 2014 and beyond

200

100

50

0

150

2012 2013 2014

450

Actual & forecast risked resource additions2009-2015 (mmboe)

2009 Actual

400

350

300

250

2010 Actual

2011 Actual

2015

Actual cumulative plus possible resourcesCumulative risked prospective resource additionsRisked prospective resource additions

Actual proved plus probable additions

•Unrisked prospective portfolio of >1.5 billion boe

(350 mmboe risked)


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NorwayPL378: Grosbeak

UKP1875 ErneStingray

NorwayPL374S: Blabaer

Bonneville

Carnaby

VietnamBlock 12W: CS NW


Acquire Licence

Gate

Drill Decision Gate

AppraisalApproval Gate

ProjectExtension

Gate M E A P

N o r t h S e a

A s i

a

Pre-Development

Spaniards

Coaster

Cougar Rapide

Rocket

K-32Badhra South

Badhra-7

New

York

Typhoon

Lacewing

Cyclone

Tupai

AnakondaB Sedang

KakakTua

B Kecil

Sambar

CRT

Silver

Sillago

Singa /Kuda Laut

PeudawaRayeu

AlurKacang

BiawakBesar

Matang

Benteng

Baroosh

Badhra-6 Parh

VietnamBlock 12W: CS Cau

VietnamBlock 087/03 CRD

PakistanKadanwari K-30

Norfolk

Moth E.

Moth S.

Cornet

LEADS PROSPECTS

Dino

Recent acquisitions add to overall portfolio value

Luno II

MATUREPROSPECTS

UNDER APPRAISAL

250

Net NPV10 $mm

>10 >25 >50$3bn success case

NPV (>$400mm EMV)

Exploration – North Sea


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• Targeted play led exploration

• Leveraging extensive datasets andgeophysical expertise

• Pushing plays beyond their currentlyunderstood limits – wider and deeper

• Future growth from within the portfolioand through new acquisitions and/or

licence awards

• Targeting 7-8 wells in 2012 withcombined gross mean prospectiveresource estimate of >350 mmboe

Exploration North SeaOverview



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• Premier has the regional database to pursueamplitude supported Tertiary prospectsthroughout the Central North Sea

• 3 firm wells to be drilled in 2012 targetingEocene prospects: Carnaby, Coaster andCyclone

– Combined gross prospective resourceestimate of 48-115-225 mmbo

• The Stringray prospect is attemptingto push the boundaries of theJurassic play fairway to the North

– Gross prospective resourceestimate of 12-30-90 mmbo

Exploration North SeaPushing the plays wider

Cyclone

Coaster

Stingray

Varadero

CarnabyCatcher N & E

Eocene ( Lower Tay) amplitude extraction

Burgman

2km

Coaster Tay Amplitudes

Catcher EastDiscovery

Coaster Prospect

Eocene Turbidite Sand Fairway

Carnaby

Appraisal – North Sea


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ppGreater Fyne Area

• Fyne Area entry – seeking incrementalreserves to reach development threshold

• Erne and Fyne Appraisal encountered

hydrocarbons but limited impact onreserves for Greater Fyne Area

• Reserves insufficient for standalonedevelopment

• Economics of tieback to nearby hostFPSOs do not currently meet Premiercorporate hurdles

• Discussions with partners ongoing

East Fyne

Erne



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Cyclone (P1784) (21/7b)

• Premier 70% equity, block awarded in 2010

• Gross prospective resource estimate (on block)

– 20-35-50 mmboe (Tay reservoir)• Risk assessment: moderate

– Critical factor: oil column

• Well planned for Q3 2012

pPushing the play wider ... Cyclone

Amplitude extractionGreen - oil?Yellow - gas

Cyclone amplitude responseon far stack data

Balder

2km

Cyclone

Cyclone



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Norfolk (P1887) (12/16b & 12/17b)

• Premier 25% equity, block awarded in 26th Round

• Gross prospective resource estimate (on licence)

– 20-146-495 mmboe• Risk assessment: high

– Critical factor: hydrocarbon charge and quality

• Prospect maturation ongoing

pPushing the plays wider ... 2013

Norfolk

Norfolk Norfolk

NNW SSEEW



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• Potential exists for deeperunderexplored fairways inthe North Sea

• In 2012, Premier will drill two prospectstargeting this deeper potential:Lacewing (Triassic target) and Luno II(Jurassic target)

• Combined gross prospective resourcepotential of 100-200-400+ mmbo

• Additional prospect maturation ongoingfor drilling in 2013 and beyond

pPushing the plays deeper

Lacewing

Luno II



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Pushing the plays deeper ... Luno II

Luno II (PL 359)• Premier equity 30%• Greater Luno is a regional high

– Focus for oil migration – Regional top seal drapes the high – Jurassic/Triassic reservoirs flank the high and,

where fractured, basement is also a reservoir – ~2,000 mmboe discovered to date

• Key play risks – Reservoir presence on the margins of the high – Lateral seal

Johan Sverdrup

PL 359

BCU Time MapC.I. 100 ms

Luno/Apollo

Ragnarrock

10km

Luno II Prospect

• Luno II is on the Southwest margin of the Johan Sverdrup high• Mesozoic sand presence interpreted from seismic and local well data

• Gross prospective resource estimate: 125mmbo (mean)

• Risk assessment: moderate – Critical factor: lateral seal




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Lacewing (P1181, 23/21 & 23/22b)

• Gross prospective resource estimate(on block)

– 50-70-90 mmboe• Risk assessment: high

– Critical factor: trap effectivenessand reservoir quality

• Transfer of 37.3% and operatorship toConocoPhillips plus partial carry

– Premier’s retained equity in theblock will be 20.2%

• ConocoPhillips considerable HPHT

experience


Top Triassic Depth Map

Pushing the plays deeper ... Lacewing

Exploration – Asia


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• Play led approach in the Nam ConSon Basin

– North West Chim Sáo Appraisal

– Kuda/Singa Laut wells planned – Prospect maturation for 2013

• Adding gas reserves

– Anoa Deep success

– Biawak Besar planned for lateMarch

– Matang will spud Q3 2012

• Pushing the frontiers

– Benteng expected to spud lateMarch

Overview

Benteng

Chim Sáo

Anoa Deep,Biawak Besar

MatangKuda/Singa Laut



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Kuda/Singa Laut ... 1H 2013

Fluid Detection Volume – 3D Inversion

4 km

Combined Depth Structure Map

- 3 2 0

0 m

Kuda/Singa Laut (Tuna Block)

• Premier 65% equity and Operator

• Faulted dip closed structure up dip from a proven source

kitchen to the east – Primary reservoir target is Miocene in the Kuda Laut

segment and Oligocene in the Singa Laut segment

• Risk assessment: low (amplitude supported)

• Gross prospective resource estimate: 60-100-140 mmbo

• Well planned for 1H 2013

Kuda Segment Singa Segment Singa Laut

Kuda Laut

Singa Laut



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Anoa Deep (Natuna Sea Block A)

• Premier 28.67% equity and Operator

• Drilled as an exploration tail to the WL-5 development well

• Encountered ~300 feet of fractured Lama Sandstones

• Lama formation tested and flowed gas

– 17 mmscf/d through a 48/64 inch choke

– Estimated total gas in place of 70-100-150 bcf

• The well will be tied-in to the Anoa facility

• Significant follow-on potential

– Similar sized structures are

mapped at the Top Lama to thenorth and east of Anoa Deep

Anoa Deep success

Top Lama DepthC.I.=100 feet

WL

1 Km

Anoa DeepDiscovery

Anoa North

2 Km

PRIMARY TARGET

NW SE

Anoa Deep (WL-5X)PTD 10850 ft MD (9550 ft TVDss)

Top Lama



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Benteng (Buton Block)

• Premier 30% equity, operated by Japex

• Gross prospective resource estimate:

– 77 mmboe (mean)• Risk assessment: high

– Critical factor: trap presence

• Well planned for late March

Buton Block

Bulu-1

Benteng-1PTD 3200m MD

PTD

2 Km2 Km

PRIMARY TARGET

NW SE

Potential play opener ... Benteng

Exploration – MEAPE t i t ff h K


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L10A & L10B

• Potential to extend successful plays tothe south into Kenya

• 2535 km2 of 3D seismic successfullyacquired in Q4 2011

– Processing of 3D seismic to becompleted by year-end

• 1030 km of 2D successfully acquired in

Q1 2012

– Processing to be completed in Q22012

• Preliminary data sets show good quality

Entry into offshore Kenya

Test line from the 3D survey

E l ti d illi 2012


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Exploration drilling 2012

17 exploration and appraisal wells planned forthe remainder of 2012, targeting ~200 mmboe

of net unrisked prospective resourceContingent Wells

Firm Wells: Rig Contracted

Firm Wells: Rig TBC

All well timings are subject to revision for operational reasons

Q1 Q2 Q3 Q4Vietnam Block 12W Chim Sáo NW Appraisal 17 Low

Indonesia Buton Benteng-1 77 High

Natuna Sea Block A Biawak Besar 15 Low

Block A Aceh Matang 40 Low

Norway PL359 Luno II 125 Moderate

UK P1430 Carnaby 34 Low

P1812 Coaster 50 High

P1430 Bonneville TBC Low

P1212/P1771 Stingray 32 Moderate

P1784 Cyclone 35 Moderate

P1655 Spaniards 32 High

P1181 Lacewing 70 High

Pakistan Kadanwari K-32 7 Low

Bhit-Badhra Badhra South Deepening-1 38 High

Badhra-7 10 High

Mauritania Commitment well TBC TBC

Middle East - Africa - Pakistan

Asia

2012 Mean gross unrisked

resource (mmboe) Risk

North Sea

PRA 01

Weatherford 812

Bredford Dolphin

Sedco 711

Sedco 711

Glomar Arctic III

Wilphoenix

Maersk Resiliant

Wilphoenix

West Callisto

ENSCO 107

Sedco 711

Wells to watch in 2012

2012 N V t f


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2012 New Venture focus

North Sea (Rift theme)

• UK and Norway Licence Rounds

• Potential adds through acquisition

MEAP (Rift & Frontal Fold Belt themes)

• East Mediterranean and Egypt

• Pakistan and Iraq

• Expanding Premier’s acreage position inEast Africa

Asia (Rift & Frontal Fold Belt themes)

• Andaman Sea• East Vietnam

• Frontier Basins of East Indonesia

E ploration


45/61


Exploration

Key messages...

• Portfolio of >1.5 billion boe of unrisked potential

• Wells to watch

– North Sea: Carnaby, Coaster, Cyclone and Luno II

– Asia: Anoa Deep, Biawak Besar and Chim Sáo North Westappraisal

• On track to deliver material programme in 2013 and beyond

• New Venture focus on basins with geologies that we understand

Summary


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Summary

What can you expect from Premier?


47/61


Already in 2012...

• Solan

• Anoa Deep

• EnCore Oil

• Finance

–

–

–

–

Board approval

A new exploration play beneath Anoa

Completed acquisition and Cladhan sale

Cash/undrawn facilities increased to $1.4 bn

Forward plan...

• Production

• Developments

• Exploration

• Acquisitions

• Cash flow

–

–

–

–

–

Rising production to 100,000 boepd

Delivery on time, on budget, operated

Enhancing portfolio materiality

Where we can add value

Increasing to $2 bn per annum

What can you expect from Premier?

Appendix


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Appendix

Group taxation position


49/61


Group taxation position

Overseas

Prior period provisions

UK

PRT

CT

Prior period revisions

Current charge

Deferred tax credits

Tax credit for the year


$m

56.9

25.9

Nil

(21.3)

61.4

(90.4)

(29.0)

Allowances brought forward

Net additions in 2011 excluding RFES

RFES changes

Tax allowances carried forward*

UK Tax Allowance Positionat 31 Dec 2011

$m

1,112

204

44

1,360


$m

60.1

72.1

17.2

nil

(2.1)

147.3

(177.0)

(29.7)

* fully recognised as deferred tax asset

Other developments


50/61


Other developments

• Caledonia will be a tieback to Balmoralbut with gas lift from Britannia

• Sanction in 2012 with first oil in 2014

• New “Small Field Allowance” expected

Block A Aceh (Vietnam)

• Project sanction delayed

– Facilities sharing agreement with Arun

not completed (Arun owner is sellingthe asset)

– EPCI bid: decision taken to re-tender

• First gas is now scheduled for mid-2015

Caledonia (UK)

Other developments


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Other developments

Bream (Norway) Frøy (Norway)

• Work on the stand-alone developmentremains on hold

• Discussions on joint development areunderway with other operators

• Focus is Frigg Gamma Delta where anew operator has recently taken over

• First oil for Froy modelled for 2017

• Development plan progressing and theFPSO has been selected

• FEED is underway on both the FPSOand the subsea scope

• FPSO contract expected soon

• Project sanction is planned for Q3 2012,with first oil in 2015

End 2011 2P reserves and contingent resources


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End 2011 2P reserves and contingent resources

North Sea Asia MEAP Total

2P ReservesOn production 36.8 74.8 32.5 144.1

Approved fordevelopment 16.6 33.7 5.1 55.5

Justified fordevelopment

71.8 24.1 0.8 96.7

Total Reserves 125.2 132.6 38.5 296.3

2C ContingentResources

Developmentpending

52.9 7.4 1.0 61.3

Un-clarified or on hold

16.1 32.9 15.7 64.6

Development notcurrently viable

27.6 63.9 12.8 104.4

Total ContingentResources

96.6 104.2 29.5 230.3

Total Reserves & ContingentResources

221.8 236.8 68.0 526.6

These figures do not include prospective resources

Prospective resource portfolio


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Unrisked Resource Portfolio

Risked Resource Portfolio

Discovered resourceunder appraisal 33 mmboe

Leads196 mmboe

Prospects160 mmboe

Total1,729

mmboe

Total373

mmboe

• Unrisked prospective resource portfolioof 1,696 mmboe

• Portfolio changes from 2010:

– Increased lead inventory in Kenya,Norway and the UK

– Prospect inventory adjusted post2011 drilling

• Risked prospective resource portfolio of 356 mmboe

– 160 mmboe in prospects

– 196 mmboe in leads

– Focus to lead and prospectmaturation in 2012

Prospective resource portfolio

Discovered resourceunder appraisal 17 mmboe

Leads1,186 mmboe

Prospects510 mmboe

Recent acquisitions add to overall portfolio volume


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UKP077: East FyneStingray

NorwayPL374S: Blabaer

Bonneville

Carnaby

VietnamBlock 12W: CS NW


Acquire LicenceGate

Drill Decision Gate

AppraisalApproval Gate

ProjectExtension

Gate M E A

P

N o r t h

S e a

A s

i a

Pre-Development

Spaniards

Coaster

Cougar Rapide

Rocket

K-32Badhra South

Badhra-7

NewYork

Typhoon

Lacewing

Cyclone

Tupai

Anakonda

B Sedang

KakakTua

B Kecil

Sambar

CRT

SilverSillago

Singa /Kuda Laut

PeudawaRayeu

AlurKacang

BiawakBesar

Matang

Benteng

Baroosh

Badhra-6 Parh

Norfolk

Moth E.

Moth S.

Cornet

Dino

Luno II

Recent acquisitions add to overall portfolio volume

LEADS PROSPECTS MATUREPROSPECTS

UNDER APPRAISAL


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Carnaby

Carnaby

Carnaby (28/9)

• Premier 35% equity

• Gross prospective resource estimate

– 15-30-50 mmbo (Tay reservoir)

• Expected phase oil – Gas in shallower Eocene targets (Upper Tay)

• New 3D seismic data work ongoing


Varadero

Carnaby Catcher N & E

Catcher Main

Catcher E

Carnaby

Varadero

NS

Lower Tay

Upper Tay

Burgman

Cromarty Depth Structure

Carnaby Prospect

Eocene ( Lower Tay) amplitude extraction

Carnaby

Burgman

Burgman

Exploration – North SeaCoaster


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Coaster (28/10a)

• Premier 100% equity, TAQA farmedinto 50% interest

• Gross prospective resource estimate13-50-125 mmboe (on block)

• Eocene and Palaeocene reservoirs

• Risk assessment: high

– Critical factor: trap and charge• Well due to spud Q2 2012

Rapide

Cougar

Varadero

Catcher North

JU1

Catcher Tiger

Burgman

Rocket

Paso

Bonneville Area

Vincent

Coaster

JU2

Carnaby

Exploration – North SeaStingray


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Stingray (P1212) (15/13b)

• Premier 50% equity, block awarded in 2004

• Gross prospective resource estimate (on block)

– 12-30-90 mmboe• Risk assessment: moderate

– Critical factor: trap – sealing fault to the north cannot beaccurately determined

• Planned spud date Q2 2012

g y

Stingray Prospect

Stingray

Exploration – North SeaSpaniards


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Spaniards (P1655)

• Premier equity 28% and Operator,adjacent to Scott infrastructure

• Gross prospective resource estimate: – 10-30-40 mmbo

• Risk assessment: high

– Critical factor: reservoir development

• Primary Target:

– Jurassic Galley Sands (oil)

– Appraising down dip extent of crestaloil discoveries in wells 15/21a-38zand 15/21-2


Top Galley Sand Depth

14/25a-5

Perth

H a l i b u t H o r s t

Spaniards WestRyazanian

Spaniards EastGalley

Spaniards CentralGalley

p

Exploration – AsiaBiawak Besar


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Biawak Besar (Natuna Sea Block A)

• Premier: 28.67% equity and Operator

• Gross prospective resource estimate 13-15-17 mmboe

• Risk assessment: low – Critical factor: lateral seal presence

• Potential in a stratigraphic trap down-dip of the Iguana-1discovery


Top Arang Depth

C.I.=100 metres2000m

Iguana Discovery

Biawak Besar-1

Biawak Besar PTD 5950 ft MD

Top Lama

PTD

500m

SENW

PRIMARYTARGET

Biawak Besar

Exploration – AsiaMatang


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Matang (Block A Aceh)

• Premier equity 41.67%

• Gross prospective resource estimate 20-40-70 mmboe(whole structure)

• Risk assessment: low

– Critical factor: reservoir presence

– 250 BCF follow on potential in the success case


500m

EW

Top Belumai

Matang-1PTD 3000m MD

Matang

Top N4 BelumaiCarbonate

C.I.=50 metres1 Km

Matang-1

g


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22nd March 2012 | Page 60www.premier-oil.com March 2012

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